Tubing hanger

ABSTRACT

A tubing hanger and system for landing a tubing hanger in a tubing head of a wellhead with full well containment. The tubing hanger includes a cylindrical housing with a production port and a penetrator port, each extending through the cylindrical housing and each offset from a center axis of the cylindrical housing. The tubing hanger can land production tubing within a tubing head of a well head with a ratio of outer diameters of the production tubing to the tubing hanger of about 0.50.

CROSS-REFERENCE TO RELATED APPLICATION

The present application claims priority under 35 U.S.C. §119 to U.S.Provisional Patent Application No. 61/941,253, filed on Feb. 18, 2014,titled “TUBING HANGER”, is hereby incorporated by reference in itsentirety into the present application.

TECHNICAL FIELD

Aspects of the present disclosure involve a tubing hanger as well as asystem and method of landing a tubing hanger in a tubing head with fullwell containment.

BACKGROUND

During completion of oil and gas production wells, a wellhead isinstalled above a wellbore as a surface interface with the oil or gasbelow. The wellhead includes many components, one of which is a tubinghanger. The tubing hanger is a device that attaches to a topmost tubingjoint of a string of production tubing and supports the productiontubing within the wellhead. The tubing hanger also supports apenetrator, which is a device that provides an electrical interfacebetween a surface junction box and a downhole cable that extends to anelectric submersible pump (ESP) within the wellbore. Conventionally, thetubing hanger is secured in place within the tubing head of a wellheadvia a rotating flange that provides an interface between the tubinghangar and additional production tubing that leads to a surfacereservoir. Once the tubing hanger is installed in the wellhead, the ESPpumps the production fluid (e.g., oil, gas) up the production tubing,through the wellhead, and into the surface reservoir.

During completion, the tubing hanger, along with the production tubingand the penetrator, must be landed or seated into a tubing head of thewellhead. Often, to land the tubing hanger, a blowout preventer (BOP),which is a special valve or device installed above a wellhead to controlblowouts of fluid, tools and tubing, must be removed because the tubinghanger cannot fit through the bore of the BOP. By removing the BOP fromthe wellhead, the well is not contained and is, thus, susceptible toblowout during the landing process.

Conventionally, tubing hangers are landed or seated into the wellheadusing a section of production tubing of the same size as the productiontubing that hangs below the tubing hanger. This section of productiontubing also, conventionally, includes the same type and size ofthreading to couple with the tubing hanger. In this way, the top andbottom of portions of a production side of the tubing hanger are mirrorimages of each other. This practice introduces certain limitations inthe sizing and design of tubing hangers, which ultimately limits thesize of production tubing that can be landed in a particular wellbore.

With these thoughts in mind among others, aspects of a tubing hanger anda system and a method of use disclosed herein were developed.

SUMMARY

Aspects of the present disclosure can include a tubing hanger thatincludes a penetrator-feed-through port comprising a penetratorpassageway extending between openings at a top and a bottom of thepenetrator-feed-through port, the penetrator passageway defining apenetrator axis therethrough. The penetrator-feed-through port isparallel to and offset from a longitudinal axis extending between acenter points of the top surface and the bottom surface of the tubinghanger. The tubing hanger can also include a production port comprisinga production passageway extending between openings at a top and bottomof the production port. The production port is defined within a raisedneck member that extends from the top surface of the tubing hanger. Theproduction passageway defining a production axis therethrough that isparallel to and offset from the longitudinal axis.

Aspects of the present disclosure involve a tubing hanger that maximizesa size of production tubing to be landed in a wellbore using aparticular design, size, and arrangement of thread patterns on thetubing hanger and the landing tool. Utilization of the tubing hangerdescribed herein enables, for example, landing a 2.25 inch penetratorand a string of 3.5 inch EUE (external-upset-end) production tubing in a7 inch nominal bowl of a tubing head (i.e., 7 inch being an innerdiameter of the tubing head just above the landing area or load shoulderof the tubing head). The tubing hanger described herein is additionallycapable of scaling such that a ratio of outer diameters of theproduction tubing to be landed in the wellbore to the tubing hanger isabout 0.50.

Aspects of the present disclosure involve a tubing hanger including apenetrator-feed-through port and a production port. Thepenetrator-feed-through port includes a penetrator passageway extendingbetween a penetrator top end and a penetrator bottom end. Thepenetrator-feed-through port also defines a penetrator axis therethroughthat is parallel to and offset from a longitudinal axis extendingbetween a center point of a top surface and a bottom surface of thetubing hanger. The production port includes a production passagewayextending between a production top end defined in a raised neck memberextending from the top surface of the tubing hanger and a productionbottom end. The production port defines a production axis therethroughthat is parallel to and offset from the longitudinal axis, theproduction passageway comprising a bottom connection at the productionbottom end that is configured to couple with an end of a productiontubing to be landed in a tubing head of a well head, the productionpassageway comprising a top connection at the production top end that isdifferent than the bottom connection and that is configured to couplewith an end of a landing tool.

In certain implementations, the production tubing includes an outerdiameter of about 3.5 inch and the tubing hanger comprises a cylindricalhousing having an outer diameter that is less than 7 inch. The topconnection includes a top threaded connection and the bottom connectioncomprises a bottom threaded connection.

Aspects of the present disclosure involve a system of well completionincluding a tubing hanger, a penetrator, and a landing tool. The tubinghanger may include a penetrator-feed-through port and a production port.The penetrator-feed-through port includes a penetrator passagewayextending between a penetrator top end and a penetrator bottom end. Theproduction port includes a production passageway extending between aproduction top end defined in a raised neck member extending from a topsurface of the tubing hanger and a production bottom end. The productionpassageway includes a bottom connection at the production bottom endthat is configured to couple with an end of a production tubing to belanded in a tubing head of a well head, the production passagewaycomprising a top connection at the production top end that is differentthan the bottom connection and that is configured to couple with an endof a landing tool. The penetrator is configured to be positioned withinthe penetrator-feed-through port and includes electrical leads forconnecting with a surface power supply and a plurality of downhole cablefor connecting with a downhole cable or an electric submersible pump.The landing tool is configured to couple with and land the tubing hangerin the tubing head of the well head and includes a tubular body and theend including engaging features that are configured to engage withengaging features on the top connection.

Aspects of the present disclosure also include a method of wellcompletion including landing a tubing hanger in a tubing head of awellhead with a landing tool. The tubing hanger may include apenetrator-feed-through port comprising a penetrator passagewayextending between a penetrator top end and a penetrator bottom end. Thetubing hanger may additionally include a production port including aproduction passageway extending between a production top end defined ina raised neck member extending from a top surface of the tubing hangerand a production bottom end. The production passageway includes a bottomconnection at the production bottom end that is configured to couplewith an end of a production tubing to be landed in a tubing head of awell head. The production passageway also includes a top connection atthe production top end that is different than the bottom connection andthat is configured to couple with an end of the landing tool.

Additionally, other embodiments are also described and recited herein.Further, while multiple implementations are disclosed, still otherimplementations of the presently disclosed technology will becomeapparent to those skilled in the art from the following detaileddescription, which shows and describes illustrative implementations ofthe presently disclosed technology. As will be realized, the presentlydisclosed technology is capable of modification in various aspects, allwithout departing from the spirit and scope of the presently disclosedtechnology. Accordingly, the drawings and detailed description are to beregarded as illustrative in nature and not limiting.

BRIEF DESCRIPTION OF THE DRAWINGS

Example embodiments are illustrated in referenced figures of thedrawings. It is intended that the embodiments and figures disclosedherein are to be considered illustrative rather than limiting.

FIG. 1A depicts a side view of a tubing hanger;

FIG. 1B depicts a top view and a section view of the tubing hanger ofFIG. 1A;

FIG. 2 depicts a side view of a landing tool;

FIG. 3 depicts a side view of a penetrator;

FIG. 4 depicts a side view of the tubing hanger, the penetrator, thelanding tool, a check valve, and a production tube;

FIG. 5 depicts a top view and a section view of a rotating flange;

FIG. 6 depicts a top view and a section view of a lock ring that securesthe rotating flange to the wellhead;

FIG. 7 depicts a flowchart of a process for landing the tubing hanger ina wellhead;

FIG. 8 depicts a flowchart of another process for landing the tubinghanger in a wellhead; and

FIG. 9 depicts a flowchart of a process for splicing a downhole cable toa penetrator's pigtails.

DETAILED DESCRIPTION

Aspects of the present disclosure include a tubing hanger that includesa penetrator-feed-through port and a production port. Thepenetrator-feed-through port includes a penetrator passageway extendingbetween openings at a top and a bottom of the penetrator-feed-throughport. The penetrator passageway defines a penetrator axis therethroughthat is parallel to and offset from a longitudinal that extends througha center point of the top surface and the bottom surface of the tubinghanger. The production port includes a production passageway extendingbetween openings at a top and bottom of the production port. Theproduction port defines a raised neck member that extends a firstdistance from the top surface of the tubing hanger. The productionpassageway defines a production axis therethrough that is parallel toand offset from the longitudinal axis that extends through the centerpoint of the top surface and the bottom surface of the tubing hanger.

The tubing hanger is capable of landing a string of production tubingand a penetrator through a blowout preventer (BOP) and into a tubinghead of a wellhead. Since the blowout preventer need not be removed, thewell is prevented from catastrophic blowouts while landing the tubinghanger and the attached penetrator and production tubing.

Referring to FIGS. 1A-1B, the tubing hanger 10 can include a cylindricalhousing 12 with a production port 14 and a penetrator-feed-through (PFT)16, each extending through the housing 12 and each offset from a centeraxis 18 of the cylindrical housing 12. The production port 14 caninclude a raised neck member 20 that extends upward from a top surface22 of the tubing hanger 10. The raised neck member 20 can include aproduction passageway 24 extending from a top surface 26 of the raisedneck member 20 to a bottom surface 28 of the tubing hanger 10. Theproduction passageway 24 defines a production axis 30 through thepassageway 24 that is parallel to the center axis 18 of the cylindricalhousing 12. In some implementations, parallel means substantiallyparallel. In other implementations, parallel may mean perfectlyparallel, offset from parallel by about 1 degree, 2 degrees, orotherwise. The production port 14 can include a first set of threading32 to receive a landing tool 34 at a top portion 36 of the productionpassageway 24, the production port 14 can include a second set ofthreading 38 to receive a back-pressure valve (BPV) 40 at a mid-portion42 of the production passageway 24, and the production port 14 caninclude a third set of threading 44 to receive a tubing joint 46 of aproduction tube 48 at a bottom portion 50 of the production passageway24.

While the embodiment of FIG. 1 describes three sets of threads, theproduction port 14 can include more or less sets of threading asnecessitated by the needs of the well. As an example, the first set ofthreading 32 can be, for example, 3.5 inch ACME threads. The threadingcan, however, be a different trapezoidal thread form or an altogetherdifferent thread form. The first set of threading 32 is to receivecorresponding threads from the landing tool 34, which will be discussedin reference to FIG. 2. While the embodiment of FIG. 1 describes sets ofthreading, the tubing hanger 10 can include attachment mechanisms orengaging features other than threading to couple the tubing hanger 10with the production tube 48, BPV 40, and landing tool 34.

The second set of threading 38 can be BPV threads 52 for receivingcorresponding threads of a BPV 40. The BPV threads 52 can be, forexample, 3 inch threads, 2 and ⅜ inch threads, 3.5 inch threads, amongothers. The BPV 40 can be installed in the production passageway 24 toprevent a blowout during landing of the tubing hanger 10 and afterwards.Additionally, if a tubing hanger 10 is installed in the tubing head ofthe well head without a BPV 40 in place, a lubricator can be used toinstall a BPV 40 to provide well control, should the tree assembly(i.e., valves, spools, and/or gauges above the wellhead) be removed. Inshort, the BPV 40 provides a means of well control during landing of thetubing hanger 10 and afterwards. An example of a BPV 40 can be a two-waycheck valve that will stop fluid pressure from traveling up the wellheadwhile allowing fluids to be pumped into the wellbore from above.

The third set of threading 44 is to engage with a correspondingthreading on a landing joint of a topmost tube in the string ofproduction tubing 48 to be landed in the wellbore. Thus, the tubinghanger 10 supports the weight of the string of production tubing 48,while the tubing head, within the wellhead, supports the weight of thetubing hanger 10. In particular, during landing of the tubing hanger 10,the tubing hanger 10 seats on a load shoulder of the tubing head. Thetubing hanger 10 is then held in place by lockdown pins within thetubing head. The third set of threading 44 can be, for example, 3.5 inchEUE, 8 round threads, or 3 EUE, inch 8 round threads, among others.While the third set of threading 44 is described as including certainthreading patterns, the third set of threading 44 and the correspondingthreading on the drill pipe 48 can include an altogether differentthread patterns.

Referring to FIGS. 1A-1B, the PFT port 16 can include a penetratorpassageway 54 that extends from a top surface 22 of the tubing hanger 10to the bottom surface 28 of the tubing hanger 10. The penetratorpassageway 54 defines a penetrator axis 56 through the passageway 54that is parallel to the center axis 18 of the cylindrical housing 12 ofthe tubing hanger 10. In some implementations, parallel meanssubstantially parallel. In other implementations, parallel may meanperfectly parallel, offset from parallel by about 1 degree, 2 degrees,or otherwise. The PFT port 16 is capable of securing a penetrator 58within the penetrator passageway 54 under low pressure and high pressurewell operating conditions. In the embodiment of FIG. 1, the penetratorpassageway 54 is cylindrical in order to receive a cylindricalpenetrator, but the penetrator passageway 54 can be, for example,rectangular or square, among other possible shapes. In the presentembodiment, the penetrator passageway 54 can, for example, have an innerdiameter of about 2.515 inches, 2 inches, or 2.25 inches, among others.

The production port 14 and the PFT port 16 are offset from the centeraxis 18 of the cylindrical housing 12 such that production tubing 48(e.g., standard 3.5 inch EUE) and penetrators (e.g., standard 2.25 inchouter diameter) can be coupled with the tubing hanger 10 and the tubinghanger 10 can be landed through a BOP 60 having a drift of, for example,7 inches or 7 and 1/16 inches. As seen in the embodiment of FIG. 1B, thecylindrical housing 12 defines a circular, outer perimeter with thecenter axis 18 in the center of the tubing hanger 10. The productionport 14 and the PFT port 16 are positioned within the circular, outerperimeter and the respective production axis 30 and penetrator axis 56are offset from the center axis 18 of the tubing hanger 10. In certaintubing hanger 10 variations, the BOP 60 must be removed in order toinstall a tubing hanger 10 because the hanger 10 is too large to fitwithin the bore of the BOP 60. With the offset design and the closetolerances between the production port 14 and the PFT port 16, thetubing hanger 10 is sized to fit through the BOP 60 while the BOP 60 ison the wellhead. Thus, the well can be further controlled by landing thetubing hanger 10 in the well head while the BOP 60 is still operating.

Still referring to FIGS. 1A-1B, example dimensions of the tubing hanger10 can include a cylindrical housing 12 diameter [A] of about 6.985inches and a height [C] from the top surface 22 to the bottom surface 28of the tubing hanger 10 of about 5.765 inches. The raised neck 20 canextend upwards [D] from the top surface 22 of the cylindrical outerhousing 12 about 2.485 inches such that a total height [B] of the tubinghanger 10 is about 8.25 inches. The penetrator port 16 can include aninner diameter [E] of about 2.515 inches, while the production port 14can have various inner diameter widths throughout the productionpassageway 24 to accommodate the first, second, and third sets ofthreads. A center point [F] of the production port 14 can be about 1.375inches offset from the center axis 18 of the cylindrical housing 12 [G],which is located about 3.4925 inches from an outer edge of thecylindrical housing 12. A center point of the PFT port 16 [H] can beabout 1.885 inches offset from the center point of the cylindricalhousing 12 [G]. A furthest portion of the raised neck 20 that extendsacross the top surface 22 of the cylindrical housing 12 [I] can be about3.750 inches, while the remaining portion that extends across the topsurface 22 of the cylindrical housing 12 [J] can be about 3.235 inches.While these and other dimensions can be seen on FIGS. 1A-1B, thedimensions are intended to be illustrative and can be altered withoutchanging the scope of the disclosure.

Example materials for construction of the tubing hanger 10 and landingtool 34 can be those materials which would be known to people havingordinary skill in the art, and can include steel, among other metals.For example, the material can be 4130 steel.

FIG. 2 depicts a landing tool 34 that is configured to engage with thetubing hanger 10 and to deliver and position the tubing hanger 10 withinthe tubing head of the wellhead. The landing tool 34 can include atubular body 62 that includes a first end 68 with a first thread pattern64 at a bottom side of the landing tool 34 and a second end 70 with asecond thread pattern 66 on a topside of the landing tool 34. The firstthread pattern 64 can be a male thread pattern that corresponds to thefirst set of threads 32 on the tubing hanger 10. As an example, thefirst thread pattern 64 can be 3.5 inch ACME threads, among others, thatmatingly engage with the female thread pattern on the first set ofthreads 32 on the tubing hanger 10. The second thread pattern 66 can bea female thread pattern and can be, for example, 3.5 inch EUE, 8 roundthreads. The second thread pattern 66 can engage with similarly sizeddrill pipe to that of the production tubing 48 that couples with theproduction port 14 of the tubing hanger 10.

During landing of the tubing hanger 10, the landing tool 34 is engagedwith the tubing hanger 10 by threading the landing tool 34 onto thetubing hanger 10. The tubing hanger 10 is subsequently lowered into thewellhead until the tubing hanger 10 is seated against the load shoulderof the tubing head. The tubing hanger 10 can be positioned appropriatelyin the tubing head by adjusting the landing tool 34. Once the tubinghanger 10 is properly in place, the tubing hanger 10 can be secured orlocked in place. The tubing hanger 10 can be set in place by engaginglockdown pins that secure the tubing hanger 10 in its orientation withinthe tubing head. Then, the BOP can be removed and a rotating flange canbe attached to the tubing head to secure the tubing hanger 10 in place.At this point, the tree assembly can be installed. In one non-limitingexample, a length [K] of the landing tool 34 can be 24 inches.

In the embodiments of FIGS. 1-2, the diameter of the production port 14on the top surface 22 of the tubing hanger 10 can be smaller than adiameter of the production port 14 on the bottom surface 28 of thetubing hanger 10. Similarly, the size of the first set of threads 32 onthe tubing hanger 10 can be a smaller diameter than a diameter of thethird set of threads 44 in the tubing hanger 10. Once the tubing hanger10 is landed in the wellhead and secured to the tubing head by thelockdown pins, the landing tool 34 and the BOP 60 are then removed. Atthis point, a rotating flange 72 and a lock ring 74 are positioned abovethe tubing hanger 10 to provide a seal or interface between the tubinghanger 10 and the tree assembly. The rotating flange 72 can includeports that match or line-up with the production port 14 and PFT port 16of the tubing hanger 10. In the disclosed embodiment, the rotatingflange 72 is fitted over the tubing hanger 10 and the rotating flange 72contacts an outer ring portion of the top surface 22 of the tubinghanger 10. The lock ring 74 subsequently secures the rotating flange 72and the tubing hanger 10 in place within the wellhead. Thus, in order toaccommodate the outer ring portion of the rotating flange 72 thatcontacts the top surface 22 of the tubing hanger 10, the production port14 and the PFT port 16 must be positioned within the outer ring portionin order to be unobstructed by the rotating flange 72. In addition, theproduction port 14 and the PFT port 16 must be positioned far enoughapart so that each respective port can be individually sealed by theports in the rotating flange 72. Since the bottom side 28 of the tubinghanger 10 is not constrained by the rotating flange 78 in a similarmanner, the diameter of the production port 14 on the bottom 28 of thetubing hanger 10 can be larger than the diameter of the production port14 on the top side of the tubing hanger 10. Thus, relatively largerdiameter production tubing 48 can be landed in a wellbore by using arelatively smaller diameter landing tool 34 that engages with arelatively smaller diameter production port 14 on the top surface 22 ofthe tubing hanger 10 because the production port 14 can be morecentrally positioned such that the rotating flange will not obstruct therelatively smaller diameter production port 14 on the top surface 22 ofthe tubing hanger 10.

As stated previously, it is conventional to use a short section ofproduction tubing 48, called a “landing joint,” that is identical inshape and thread pattern to the production tubing 48 that is landedwithin the well head to land the tubing hanger 10 in the tubing head.Conventionally, the landing joint has first and second thread patterns64, 66 that are the same.

Still referring to FIGS. 1-2, the raised neck member 20 can include anouter diameter [N]. And, as stated previously, the cylindrical housing12 of the tubing hanger 10 can include an outer diameter [A]. A ratio ofthe outer diameter [N] of the raised neck member 20 to the outerdiameter [A] of the cylindrical housing 12 of the tubing hanger 10 canbe less than 0.6. In another embodiment, the ratio of the outer diameter[N] of the raised neck member 20 to the outer diameter [A] of thecylindrical housing 12 of the tubing hanger 10 can be less than 0.575.In another embodiment, the ratio of the outer diameter [N] of the raisedneck member 20 to the outer diameter [A] of the cylindrical housing 12of the tubing hanger 10 can be less than 0.55. In another embodiment,the ratio of the outer diameter [N] of the raised neck member 20 to theouter diameter [A] of the cylindrical housing 12 of the tubing hanger 10can be less than 0.5. In another embodiment, the ratio of the outerdiameter [N] of the raised neck member 20 to the outer diameter [A] ofthe cylindrical housing 12 of the tubing hanger 10 can be less than0.525. In another embodiment, the ratio of the outer diameter [N] of theraised neck member 20 to the outer diameter [A] of the cylindricalhousing 12 of the tubing hanger 10 can be less than 0.5. In anotherembodiment, the ratio of the outer diameter [N] of the raised neckmember 20 to the outer diameter [A] of the cylindrical housing 12 of thetubing hanger 10 can be less than 0.475. In another embodiment, theratio of the outer diameter [N] of the raised neck member 20 to theouter diameter [A] of the cylindrical housing 12 of the tubing hanger 10can be less than 0.45. In one example, the raised neck member 20 caninclude an outer diameter [N] of about 3.75 inches and the cylindricalhousing 12 of the tubing hanger 10 can include an outer diameter [A] ofabout 6.985. Thus, the ratio of the outer diameter [N] of the raisedneck member 20 to the outer diameter [A] of the cylindrical housing 12of the tubing hanger 10 can be 0.537 in this example.

The ratio of the outer diameter [N] of the raised neck member 20 to theouter diameter [A] of the cylindrical housing 12 of the tubing hanger 10can be balanced with the strength capabilities of the material of thetubing hanger 10 and the load that the tubing hanger 10 will experiencein the wellhead. The raised neck member 20 cannot be sized such that thematerial cannot withstand the pressure exerted by the weight of thestring of production tubing 48 hanging from the tubing hanger 10. As anexample, the material for the tubing hanger 10 and the raised neckmember 20 can be rated to withstand pressures of up to 5,000 psi and thewall thickness of the raised neck member 20 must not be such that theintegrity of the material is compromised when the tubing hanger 10experiences the weight of the string of production tubing 48. Stateddifferently, the outer diameter [N] of the raised neck member 20 cannotbe reduced so much that the wall thickness threatens premature failureof the tubing hanger 10.

Still referring to FIGS. 1-2 and as discussed previously, in certainimplementations, the tubing hanger 10 is configured to land productiontubing 48 having an outer diameter of 3.5 inches into a tubing head of awell head having a clearance of 7 inches. That is, the tubing hanger 10is seated on a load shoulder where an inner diameter of the tubing headjust above the load shoulder is 7 inches. In a tubing head of this size,the cylindrical housing 12 of the tubing hanger 10 may include an outerdiameter [A] of about 6.985 inches. Thus, a ratio of the outer diameterof production tubing 48 to the outer diameter [A] of the tubing hanger10 can be about 0.50. In certain implementations, the ratio of the outerdiameter of production tubing 48 to the outer diameter [A] of the tubinghanger 10 can be greater than 0.50. In certain implementations, theratio of the outer diameter of production tubing 48 to the outerdiameter [A] of the tubing hanger 10 can be greater than 0.45. Incertain implementations, the ratio of the outer diameter of productiontubing 48 to the outer diameter [A] of the tubing hanger 10 can begreater than 0.40. A full listing of dimensions of an example embodimentof the tubing hanger 10 can be found in the Appendix to theSpecification.

In certain implementations, the production tubing 48 has an outerdiameter of greater than 3.0 inches. In certain instances, theproduction tubing 48 has an outer diameter of greater than 3.25 inches.In certain instances, the production tubing 48 has an outer diameter ofgreater than 3.40 inches. In certain instances, the production tubing 48has an outer diameter of greater than 3.45 inches. In certain instances,the production tubing 48 has an outer diameter of about 3.5 inches. Incertain instances, the production tubing 48 has an outer diameter ofless than 4.0 inches. In certain instances, the production tubing 48 hasan outer diameter of less than 3.75 inches. In certain instances, theproduction tubing 48 has an outer diameter of less than 3.60 inches. Incertain instances, the production tubing 48 has an outer diameter ofless than 3.55 inches.

While the disclosed embodiments refer to a rotating flange 72 and a lockring 74 supporting the tubing hanger 10 within the wellhead, othermechanisms can similarly provide a seal between the tubing hanger 10 andthe tree assembly. The disclosure of a rotating flange 72 and lock ring74 are not intended to be limiting as other mechanism can similarlysupport the tubing hanger 10 within the wellhead.

As an example, to land 3.5 inch production tubing 48 down a 7 inch bowlof a tubing head and through a BOP 60 with about a 7 inch drift, atubing hanger 10 can include a first set of threads 32 that are 3.5 inchACME threads, which are smaller, non-tapered threads compared to 3.5inch EUE 8 round threads which generally require a taper, and a thirdset of threads 44 that are 3.5 inch EUE 8 round threads. In thisexample, the size of the first set of threads are relatively smallerthan the third set of threads (i.e., the 3.5 inch acme threads do notrequire a taper) such that the production port 14 and the PFT port 16,on the top surface 22 of the tubing hanger 10, are not obstructed by therotating flange 72.

As seen in FIG. 1B, the raised neck member 20 could not accommodate abore for 3.5 inch EUE threading. As seen at the bottom of the productionport 14, an inner diameter [O] of the bore for the third set ofthreading 44 (i.e., 3.5 EUE threading) is about 3.81 inches in diameter.And, as seen at the top of the production port, the outer diameter [N]of the entire raised neck member 20 is 3.75 inches in diameter. Thus,the inner diameter [O] of the bore for the third set of threading 44 islarger than the entirety of the raised neck member 20. Clearly, giventhe dimensions of the raised neck member 20, a 3.5 inch EUE threadingcould not be used for the first set of threads 32.

It is conventional in the industry to size down the first and third setsof threading 32, 44, while keeping them the same size, until the firstset of threading 32 can fit within the confines of the raised neckmember 20. Thus, as an example, if a bore for a 2.5 inch EUE threadingcould fit within the confines of the raised neck member 20, then aconventional practice in the industry would be to utilize a 2.5 inch EUEthreading on the bottom side of the production port 14. Utilizing EUEthreading is common in the drilling industry and, thus, it makes sensethat, conventionally, EUE threading is utilized on both ends of thetubing hanger 10. Doing so, however, limits the size of productiontubing 48 to be landed in a wellhead.

Utilizing a non-tapered thread (i.e., 3.5 inch ACME) on the first set ofthreading 32 enables a 3.5 inch diameter section of production tubing(i.e., landing tool) with a non-tapered thread to fit within theconfines of the raised neck member 20. Stated differently, the firstthread pattern 64 on the landing tool 34 that engages with the first setof threads 32 on the tubing hanger 10 can still be machined on the samesize production tubing 48 as that of the third set of threading 44. Inother words, 3.5 inch outer diameter production tubing can be machinedto include either an EUE or trapezoidal (e.g., ACME) threadconfiguration.

FIG. 3 depicts a penetrator 58 that is configured to couple with thetubing hanger 10 in the PFT port 16. The penetrator 58 is an electricalinterface between a surface junction box and an ESP downhole. Power forthe ESP is routed from the junction box to the penetrator 58 and then tothe ESP via electrical wires known as REDA cables or ESP cables. Atopside 76 of the penetrator 58 can include three copper pins or leadsfor attaching to the electrical wires from the junction box. Thepenetrator 58 can include a solid body 78 that extends a length of thePFT port 16. On a downhole side of the penetrator 58, three wires knownas pigtails 80 extend downward. The pigtails 80 will be spliced with adownhole cable, which spans a length of the string of tubing, all of theway down to the ESP. The penetrator 58 can include a collar 82 on thedownhole side of the penetrator 58 that is wider than an outer diameterof the penetrator 58. Anti-rotation bolts 84 can secure the collar 82 tothe bottom surface 28 of the tubing hanger 10 to prevent rotation of thepenetrator 58 within the penetrator passageway 54. And, the penetrator58 can also include a surface lock ring nut 86 on the topside of thepenetrator 58 to further secure the penetrator 58 within the penetratorpassageway 54 and prevent the penetrator 58 from falling through the PFTport 16. The penetrator 58 can also include o-ring seals 88 for sealingthe penetrator 58 within the tubing hanger 10, as well o-ring seals 88for sealing the penetrator within portions of the tree assembly. In onenon-limiting example, the outer diameter [L] of the penetrator 58 can beabout 2.25 inches and a length [M] of the solid body 78 can be about 14inches. The pigtails 80 can extend from the downhole side of thepenetrator 58 about 10 feet or 8 feet, among other possible distances.

In certain implementations, the outer diameter [L] of the penetrator 58can be greater than 1.5 inches. In certain instances, the outer diameter[L] of the penetrator 58 can be greater than 1.75 inches. In certaininstances, the outer diameter [L] of the penetrator 58 can be greaterthan 2.0 inches. In certain instances, the outer diameter [L] of thepenetrator 58 can be about 2.25 inches. In certain instances, the outerdiameter [L] of the penetrator 58 can be less 3.0 inches. In certaininstances, the outer diameter [L] of the penetrator 58 can be less than2.75 inches. In certain instances, the outer diameter [L] of thepenetrator 58 can be less than 2.5 inches.

FIG. 4 depicts a system for well control. In particular, the figuredepicts a tubing hanger 10 with a penetrator 58 installed in thepenetrator passageway 54, a landing tool 34 installed in the first setof threading 32, a BPV 40 installed in the second set of threading 38,and a production tube 48 installed in the third set of threading 44.This system can be landed through a bore of a BOP 60 such that thetubing hanger 10 seats against the load shoulder of a tubing head withinthe wellhead. Once the system is in the wellhead, lockout pins may beengaged to secure a positioning of the tubing hanger 10 within thetubing head. At this point, the landing tool 34 can be removed. Also, ifthe BPV 40 was not installed prior to landing, the BPV 40 may beinstalled after the landing tool 34 is removed. The BOP 60 can then beremoved from the wellhead and a rotating flange 72 can be installed onthe wellhead to secure the tubing hanger 10 within the tubing head.Next, the tree assembly can be installed on the wellhead and the wellcan be controlled with the various controls on the tree assembly. Atthis point, the BPV 40 can be removed.

FIG. 5 illustrates a rotating flange 72 for use in securing the tubinghanger 10 in place within the wellhead. The rotating flange 72 caninclude ports that are generally coextensive with the production port 14and the PFT port 16, when the rotating flange 72 is positioned above thetubing hanger 10. As previously stated, the rotating flange 72 and thelock ring 74 extend over an outer ring portion of the top surface 22 ofthe tubing hanger 10. The production port 14 and the PFT port 16 arepositioned on the tubing hanger 10 such that when the rotating flange 72and lock ring 74 are installed, the ports are within the outer ringportion that are being supported by the rotating flange 72. While thedisclosed embodiments refer to a rotating flange 72, other designs arepossible to seal or interface between the tubing hanger 10 and the treeassembly.

When coupled with the tubing hanger 10, the raised neck member 20 ispartially received within a production side lower opening 102 on abottom surface 104 of the rotating flange 72. Coextensive with theproduction side lower opening 102 is a production side upper opening 106extending from a top surface 108 of the rotating flange 72. As seen inFIG. 5, the production side upper opening 106 is sized for a taperedthread, such as a 3.5 inch EUE (external-upset-end) threading. Also seenin FIG. 5, is a test valve 110 that may be pressurized to ensure anadequate seal between the rotating flange 72 and the raised neck member20 of the tubing hanger, between the rotating flange 72 and theproduction tubing 48 extending out the production side upper opening106, and between the rotating flange 72 and the penetrator 58. Incertain implementations, the test valve 110 is a ½ inch diameter testvalve.

In one implementation, a tubing hanger 10 coupled with 3.5 inch EUEproduction tubing 48 and a 2.25 inch penetrator 58 can be landed in atubing head having a 7 inch bowl when the first set of threading 32 is3.5 inch ACME threads. As discussed previously, conventional tubinghangers 10 utilize the same threading for the first and third sets ofthreading 32, 44. There is, however, insufficient room or tolerances inthe raised neck member 20 for 3.5 inch EUE threading. To remedy thischallenge, conventional tubing hangers 10 reduce the threading sizes forthe first and third sets of threading, as well as the size of productiontubing, to accommodate EUE threading on both sides of the tubing hanger.

As such, when utilizing a non-tapered threading, such as, for example,ACME threads, larger production tubing 48 can be used on both ends ofthe tubing hanger 10 because the non-tapered threads generally requiresless machining of the raised neck member 20.

FIG. 6 illustrates the lock ring 74 for use in securing the rotatingflange 72 above the tubing hanger 10 within the wellhead. FIGS. 5-6illustrate the nesting relation between the tubing hanger 10, rotatingflange 72, and the lock ring 74. As illustrated, once the tubing hanger10 is landed in the tubing head, the rotating flange 72 is positionedabove the tubing hanger 10 with the ports being coextensive, and thelock ring 74 is secured over the rotating flange 72 such that therotating flange 72 and the tubing hanger 10 are secured sealed in place.While the disclosed embodiments refer to a lock ring 74, other designsare possible to secure the rotating flange 72 in place. For example, anytype of fastener with bolts or otherwise can be used in place of thelock ring without departing from the present disclosure.

Referring to FIG. 7, a method of controlling a well while landing atubing hanger 10 in a wellhead can include the steps of securing alanding joint of a last joint of tubing 48 to be landed in a well withina production port 14 of a tubing hanger 10 [Operation 100]. The methodcan also include installing a BPV 40 within the production port 14 ofthe tubing hanger 10 [Operation 110] and securing a landing tool 34within the production port 14 of the tubing hanger 10 [Operation 120].The method can further include securing a penetrator 58 in a PFT port 16of the tubing hanger 10 [Operation 130] and landing the tubing hanger 10through a BOP 60 and into a tubing head of a wellhead [Operation 140].Finally, the method can also include securing lockdown pins on thetubing hanger 10 [Operation 150], removing the BOP 60 [Operation 160],and installing a rotating flange 72 to the wellhead in order to securethe tubing hanger 10 within the tubing head [Operation 170].

Referring to FIG. 8, another method of controlling a well while landinga tubing hanger 10 in a wellhead can include measuring a first distancefrom a top of a bore of a BOP 60 to a center point of a lockdown pin inthe tubing head [Operation 200]. The method can further includepositioning the tubing hanger 10 over the bore of the BOP 60 [Operation210] and identifying a point on the landing tool 34 that is the firstdistance upward from a top surface 22 of the tubing hanger 10 [Operation220]. The method then can include landing the tubing hanger 10 throughthe bore of the BOP 60 until the identified point on the landing tool 34is coextensive or flush with the top of the bore of the BOP 60[Operation 230]. When the points are flush, the tubing hanger 10 issufficiently landed within the load shoulder of the tubing head suchthat the lockdown pins can be engaged and the tubing hanger 10 can besecured within the wellhead.

Referring to FIG. 9, another method of controlling a well while landinga tubing hanger 10 in a wellhead can include splicing the pigtails 80 ofthe penetrator 58 with the downhole cable while the BOP 60 is connectedto the wellhead. The splicing is necessary in order to supply power,which is routed to the penetrator 58, to the ESP. The splicing can beperformed outside of the wellbore, before the tubing hanger 10 is landedinto the wellhead, and while the BOP 60 is connected to the wellhead.Additionally, enough drill pipe 48 can be exposed out of the wellboresuch that the downhole cable is also exposed out of the wellbore for thesplicing. The method can include coupling the drill pipe 48 to thetubing hanger 10 [Operation 300] and positioning the penetrator 58 inthe PFT port 16 of the tubing hanger 10, while hanging the pigtailsflush against the drill pipe 48 [Operation 310]. The method can alsoinclude identifying a point where a shortest of the pigtails 80 overlapswith the downhole cable, which is also positioned flush with the drillpipe 48 [Operation 320]. The method can further include removing thepenetrator 58 from the tubing hanger 10 [Operation 330], splicing thepigtails 80 with the downhole cable where the downhole cable overlapswith the shortest of the pigtails 80 [Operation 340], reposition thepenetrator 58 in the PFT port 16 of the tubing hanger 10 [Operation350], and landing the tubing hanger 10 in the tubing head of thewellhead [Operation 360].

Although various representative embodiments of this invention have beendescribed above with a certain degree of particularity, those skilled inthe art could make numerous alterations to the disclosed embodimentswithout departing from the spirit or scope of the inventive subjectmatter set forth in the specification. All directional references (e.g.,top, bottom) are only used for identification purposes to aid thereader's understanding of the embodiments of the present invention, anddo not create limitations, particularly as to the position, orientation,or use of the invention unless specifically set forth in the claims.Joinder references (e.g., attached, coupled, connected, and the like)are to be construed broadly and can include intermediate members betweena connection of elements and relative movement between elements. Assuch, joinder references do not necessarily infer that two elements aredirectly connected and in fixed relation to each other.

In methodologies directly or indirectly set forth herein, various stepsand operations are described in one possible order of operation, butthose skilled in the art will recognize that steps and operations can berearranged, replaced, or eliminated without necessarily departing fromthe spirit and scope of the present invention. It is intended that allmatter contained in the above description or shown in the accompanyingdrawings shall be interpreted as illustrative only and not limiting.Changes in detail or structure can be made without departing from thespirit of the invention as defined in the appended claims.

1. A tubing hanger comprising: a penetrator-feed-through port comprisinga penetrator passageway extending between a penetrator top end and apenetrator bottom end and defining a penetrator axis therethrough thatis parallel to and offset from a longitudinal axis extending between acenter point of a top surface and a bottom surface of the tubing hanger;and a production port comprising a production passageway extendingbetween a production top end defined in a raised neck member extendingfrom the top surface of the tubing hanger and a production bottom end,the production port defining a production axis therethrough that isparallel to and offset from the longitudinal axis, the productionpassageway comprising a bottom connection at the production bottom endthat is configured to couple with an end of a production tubing to belanded in a tubing head of a well head, the production passagewaycomprising a top connection at the production top end that is differentthan the bottom connection and that is configured to couple with an endof a landing tool.
 2. The tubing hanger of claim 1, wherein theproduction tubing comprises an outer diameter of greater than 3.25inches and less than 3.75 inches and the tubing hanger comprises acylindrical housing having an outer diameter that is 7 inches or less,wherein the top connection comprises a top threaded connection and thebottom connection comprises a bottom threaded connection.
 3. The tubinghanger of claim 2, wherein the bottom threaded connection is a taperedthreaded connection that progressively narrows as it extends from theproduction bottom end towards the production top end.
 4. The tubinghanger of claim 3, wherein the bottom threaded connection is anexternal-upset-end thread configuration.
 5. The tubing hanger of claim3, wherein the top threaded connection is a non-tapered threadedconnection.
 6. The tubing hanger of claim 5, wherein the top threadedconnection is a trapezoidal thread configuration.
 7. The tubing hangerof claim 6, wherein the trapezoidal thread configuration is an ACMEthread configuration.
 8. The tubing hanger of claim 2, wherein thepenetrator-feed-through port is configured to support a penetratorcomprising an outer diameter of greater than 1.75 inches and less than2.5 inches.
 9. The tubing hanger of claim 1, wherein a ratio of outerdiameters of the production tubing to the tubing hanger is about 0.50.10. The tubing hanger of claim 1, wherein a ratio of outer diameters ofthe raised neck member to the tubing hanger is within a range of about0.5 to about 0.6.
 11. The tubing hanger of claim 1, wherein a ratio ofouter diameters of the raised neck member to the tubing hanger is withina range of about 0.5 to about 0.55.
 12. A system of well completioncomprising, a tubing hanger comprising: a penetrator-feed-through portcomprising a penetrator passageway extending between a penetrator topend and a penetrator bottom end; and a production port comprising aproduction passageway extending between a production top end defined ina raised neck member extending from a top surface of the tubing hangerand a production bottom end, the production passageway comprising abottom connection at the production bottom end that is configured tocouple with an end of a production tubing to be landed in a tubing headof a well head, the production passageway comprising a top connection atthe production top end that is different than the bottom connection andthat is configured to couple with an end of a landing tool; a penetratorconfigured to be positioned within the penetrator-feed-through port andcomprising electrical leads for connecting with a surface power supplyand a plurality of downhole cable for connecting with a downhole cableor an electric submersible pump; and a landing tool configured to couplewith and land the tubing hanger in the tubing head of the well head andcomprising a tubular body and the end comprising engaging features thatare configured to engage with engaging features on the top connection.13. The system of claim 12, wherein the production tubing comprises anouter diameter of greater than 3.25 inches and less than 3.75 inches andthe tubing hanger comprises an outer diameter that 7 inches or less,wherein the engaging features of the top connection and the end of thelanding tool comprise non-tapered threading.
 14. The system of claim 13,wherein the non-tapered threading comprises a trapezoidal threadconfiguration.
 15. The tubing hanger of claim 13, wherein thepenetrator-feed-through port is configured to support a penetratorcomprising an outer diameter of greater than 1.75 inches and less than2.5 inches.
 16. The tubing hanger of claim 12, wherein a ratio of outerdiameters of the production tubing to the tubing hanger is about 0.50.17. A method of well completion comprising: landing a tubing hanger in atubing head of a wellhead with a landing tool, the tubing hangercomprising: a penetrator-feed-through port comprising a penetratorpassageway extending between a penetrator top end and a penetratorbottom end; and a production port comprising a production passagewayextending between a production top end defined in a raised neck memberextending from a top surface of the tubing hanger and a productionbottom end, the production passageway comprising a bottom connection atthe production bottom end that is configured to couple with an end of aproduction tubing to be landed in a tubing head of a well head, theproduction passageway comprising a top connection at the production topend that is different than the bottom connection and that is configuredto couple with an end of the landing tool.
 18. The method of claim 17,wherein the production tubing comprises an outer diameter of greaterthan 3.25 inches and less than 3.75 inches and the tubing hangercomprises an outer diameter that 7 inches or less, wherein the topconnection and the end of the landing tool comprise non-taperedthreading.
 19. The method of claim 18, wherein the non-tapered threadingcomprises a trapezoidal thread configuration.
 20. The method of claim17, wherein a ratio of outer diameters of the production tubing to thetubing hanger is about 0.50.